On-Demand Vapor Generator and Control System

ABSTRACT

The disclosed apparatus and control system produces a single, on demand, energetic gaseous working fluid from any heat source. Working fluid in a liquid phase is released into a heat exchange tube in the form of very fine droplets or atomized mist, where it is rapidly heated to its gaseous phase. The gaseous working fluid can continue to absorb heat before exiting the heat exchange tube to perform work. The disclosed system controls the release of working fluid into the heat exchange tube and/or the heat energy to which the tube is exposed, resulting in a flow of energetic gaseous working fluid that can be quickly adjusted in response to changing conditions without a large pressure vessel.

BACKGROUND

The disclosure relates to devices and methods for generating controlledflows of energetic working fluids without a pressure vessel.

Phase-change working fluids are commonly used to translate heat energyinto useful work or to transport heat from one location to another. Theuse of water as a working fluid where heat energy is absorbed to changewater into steam that is then used to perform work is well-known. Otherworking fluids such as refrigerants may be employed in a similarfashion. Many prior art energy translation systems employ a boiler toheat large quantities of water to generate a flow of steam that can thenbe used to move heat energy from the boiler to another location (as insteam heat systems) or to perform work (as in steam engines, turbines,etc.). The reserve of steam available in a pressure vessel allowssystems to respond quickly to changes in demand through controlledrelease of steam from the pressure vessel. The energy stored in suchpressure vessels presents significant hazards and may require specialsiting permits from state and local governments as well as dedicatedstaff to monitor and operate such systems.

There is a need for a non-boiler steam source that is capable ofproviding a consistent flow of steam that is responsive to changingconditions.

SUMMARY

The disclosed apparatus and control system produces a single, on demand,energetic gaseous working fluid from any heat source. Working fluid in aliquid phase is released into a heat exchange tube where it is heated toits gaseous phase. The gaseous working fluid can continue to absorb heatbefore exiting the heat exchange tube to perform work. The disclosedsystem controls the release of working fluid into the heat exchange tubeand the heat energy to which the tube is exposed, resulting in a flow ofenergetic gaseous phase working fluid that can be quickly adjusted inresponse to changing conditions without a large pressure vessel. As usedin the context of this application, “heat exchange tube” means astructure having a large surface area relative to its internal volume tofacilitate heat exchange between a source of heat energy and the workingfluid inside the heat exchange tube. It is important to note that a heatexchange tube in the context of the present invention does not contain asignificant volume of liquid phase working fluid. Liquid phase workingfluid is released into the heat exchange tube in concert with theapplication of heat to the heat exchange tube and at a rate ensuringthat liquid phase working fluid does not accumulate in the heat exchangetube. Heat exchange tube is not limited to an elongated tubular shape inthe traditional sense, and should be interpreted broadly according tothe definition given above. Whatever the shape of the heat exchangetube, it is necessary that the tube be capable of containing the workingfluid during transition from liquid to gas and also to contain thegaseous working fluid up to the maximum working pressure of the system,including a margin of safety.

Heat may be generated by means of external combustion from any fuel suchas natural gas, wood, garbage, etc. External combustion has manyadvantages relative to internal combustion, with the main advantagebeing that such systems are fuel agnostic. Any fuel that provides heatcan be used to produce work in conjunction with the disclosed apparatusand control systems, whereas internal combustion requires a specificallyrefined fuel. The disclosed apparatus and control systems are notlimited to external combustion as a source of heat. The disclosedconcepts are compatible with any form of heat, including but not limitedto waste heat in the exhaust from internal combustion engines, furnaces,kilns, etc. The term “heat exchanger” as used in this applicationapplies to any arrangement configured to facilitate movement of heatfrom one fluid to another and includes liquid to gas, liquid to liquid,and gas to gas heat exchangers. Heat exchangers are configured forspecific installed environments and take many forms that arewell-understood to those skilled in the art, all of which areencompassed by the term “heat exchanger” as used in this application.

The disclosed embodiments employ water as the working fluid, but theapparatus, methods and concepts are not limited to only water as aworking fluid. Other mediums have been used for two-phase vapor-liquidpower systems, including but not limited to ammonia, refrigerants,isobutane, and isopentane. The Organic Rankine Cycle (ORC) is named forits use of an organic, high molecular mass fluid with a liquid-vaporphase change, or boiling point, occurring at a lower temperature thanthe water-steam phase change. Organic fluids compatible with ORC systemsmay be used as working fluid in systems constructed according to thisdisclosure. Any fluid with a phase change from a liquid to a gas bymeans of heat transfer may be compatible with the present disclosure,however water steam has properties that are particularly beneficial inthe context of the disclosure systems and methods.

The gaseous phase of the working fluid is employed as an energetic fluidto do work (for example, to generate electricity) through an expander(turbine, piston engine, etc.) or to produce a controlled flow of heatedgaseous phase working fluid such as steam for process applications. Pastmethods for generating a controlled flow of steam require a boiler whichaccumulates steam in a pressure vessel and releases steam from thepressure vessel as desired to perform work. Maintaining a reservoir ofsteam means that additional demand can be quickly met by releasingadditional steam from the reservoir. However maintaining a largereservoir of pressurized steam is less efficient than generating steamon-demand in response to changing system conditions. Systems employingeven a modest size reservoir of liquid phase working fluid can requiresubstantial time before any gaseous phase working fluid is available,typically requiring that the reservoir remain heated even when there isno demand for gaseous phase working fluid. Additionally, a largereservoir of steam can present safety risks that add to the cost andcomplexity of such systems.

The present disclosure relates to a system that generates on demandgaseous phase working fluid from controlled release of liquid phaseworking fluid into a heat exchanger, and a control system to regulatethe flow of liquid phase working fluid and the heat energy to which theworking fluid is exposed. The resulting flow of gaseous phase workingfluid can be controlled in terms of its quantity, temperature andpressure and used to perform a desired work or process.

Due to the very large expansion of water when it becomes steam, thevolume and properties of the steam generated in such a system will tendto fluctuate, which is undesirable. An electronic control systemregulates the flow of water (liquid phase working fluid) into the heatexchanger and the heat energy applied to the heat exchanger to produce asteady flow of steam at a desired temperature and pressure. Informationfrom temperature and/or pressure sensors at the outlet of the heatexchanger is employed by the control system to stabilize the steamoutput in a feedback arrangement. In addition to generating a steadystate flow of steam, embodiments of disclosed systems and controlmethods are capable of increasing or decreasing the flow of steam inresponse to system inputs calling for decreased or increased work. Thecontrol system regulates the mass flow of water and the heat deliveredto the heat exchanger, which allows the system to fluctuate to anydesired power output (within equipment limits).

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a block diagram of a basic on demand steam generatingapparatus and control system according to aspects of the disclosure;

FIG. 2 is a block diagram of an on demand steam generating systemarranged to generate electricity and supplementary heat in a combinedheat and power arrangement according to aspects of the disclosure;

FIG. 3 is a perspective view of a heat exchanger showing input andoutput couplings according to aspects of the disclosure;

FIG. 4 is a schematic showing components of a representative controllerfor use in the disclosed systems and methods;

FIG. 5 is a flow chart illustrating exemplary program steps executed atsystem start up according to aspects of disclosed methods;

FIG. 6 is a flow chart illustrating alternative program steps executedat system start up according to aspects of disclosed methods;

FIG. 7 is a flow chart illustrating exemplary program steps executedduring steady state operation according to aspects of the disclosedmethods;

FIG. 8 is a flow chart illustrating alternative program steps executedduring steady state operation according to aspects of the disclosedmethods;

FIG. 9 is a flow chart illustrating exemplary program steps executedduring steady state operation of the disclosed system according toaspects of the disclosure; and

FIG. 10 is a simplified example of a heat exchange tube according toaspects of the disclosure.

DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENTS

Disclosed systems and methods will be described using water as theliquid phase working fluid and steam as the gaseous phase working fluid.Those skilled in the art will recognize that other working fluids may beemployed and that the disclosed systems and methods are not limited to awater/steam working fluid.

FIG. 1 illustrates a basic on demand steam generating system accordingto aspects of the disclosure. The system 100 includes a water tank 1,water pump 3, check valve 4 and nozzle 5 arranged to deliver water intoa heat exchanger 6 within a combustion chamber 7. Liquid water 2 ispressurized by water pump 3 to produce a pressure differential acrossnozzle 5, resulting in liquid water entering the heat exchanger 6. Thewater delivered to the heat exchanger 6 absorbs heat energy sufficientto change phase to steam, expanding rapidly as a result. The steamcontinues to absorb heat as it fills the one or more heat exchange tubes30 in the heat exchanger 6. In one disclosed embodiment, the heatexchanger 6 and combustion chamber 7 may be similar to that employed ina natural gas condensing boiler, with one or more coiled heat exchangetubes 30 arranged in a combustion chamber 7 such as that illustrated inFIG. 3. The nozzle 5 is arranged at or near an otherwise closed end ofthe heat exchange tube 30. As injected water transitions to steam, itexpands to greater than 1000 times the liquid volume, filling the tubewith steam. As newly injected water is converted to steam, new steamdisplaces steam already in the tube 30, producing a flow of steam 10away from the nozzle 5. The length of the tube 30 into which the wateris injected allows the steam to continue to absorb heat as it moves awayfrom the nozzle 5, becoming dry, superheated steam that is ideal for usein a variety of expanders to perform work. Pressure and/or temperaturesensors 8, 9 are arranged at the outlet of the heat exchanger 6 andprovide corresponding pressure P and temperature TEMP signals to acontroller 11.

The controller 11 is a programmable device with inputs, outputs, memoryand a processor, as shown in FIG. 4. The controller may be amicrocontroller and include a communication interface allowing acomputer or other input/output device to be connected for programmingand monitoring the microcontroller during operation as is known in theart. The controller 11 is programmed with one or more sets of programinstructions that are stored in memory. Data is also stored in memoryand may be used during operation of the on-demand vapor generator 100.The controller 11 may be configured to cooperate with a burnercontroller 24, provided by the manufacturer of the burner 12 to controlthe quantity of heat released into the combustion chamber 7. Thecontroller 11 adjusts operation of water pump 3 to control the mass flowof water injected into the heat exchange tube 30. Assuming the presenceof sufficient heat energy to convert injected water into steam,increased differential pressure across nozzle 5 results in increasedmass flow of water into heat exchange tube 30 and increased volume ofsteam 10 at the outlet of the heat exchanger 6. If the heat energyremains constant, increased mass flow of water results in a decrease intemperature of the steam at the outlet of the heat exchanger 6. Asdiscussed in greater detail below, control methods may vary fluid flow,heat input, or both to provide a stable flow of gaseous phase workingfluid (vapor).

According to aspects of the disclosure, the pump 3 may be driven by abrushless direct current (BLDC) motor 32 in which the torque generatedby the motor is proportional to the applied power and is adjustableusing pulse width modulation (PWM). The controller 11 adjusts the powerapplied to the pump motor 32 to vary the pressure differential acrossthe nozzle 5, which regulates the mass flow of water through the nozzle5. The relationship between power applied to the water pump motor 32 andthe mass flow of water through nozzle 5 can be established byexperimentation and stored in memory for use in the controller program,resulting in predictable delivery of water into the heat exchanger 6. Inan alternative arrangement, a mass flow sensor can be arranged to detectthe flow of water through the nozzle 5 and a signal corresponding to themeasured mass flow employed by the controller to adjust operation of thewater pump motor. Heat output of the burner 12 can be similarlyestablished by operating the burner over a range of settings toestablish control signals to the burner 12 corresponding to quantitiesof heat energy released into the combustion chamber.

FIG. 10 illustrates a simple heat exchange tube having a circular crosssection. Any heat exchange tube configuration is compatible with thedisclosed system, so long as the tube has sufficient strength to containthe steam at the pressure level needed by the expander attached to theoutput of the heat exchanger 6. One example of an expander is a steamturbine driven generator, which requires approximately 0.004 Kg persecond of superheated dry steam at a temperature of approximately350°-400° F. and pressure of about 75 psi. Steam that is too cool andwet or steam that is too hot will result in damage to the turbine 15, socontrol of the steam parameters of temperature and pressure is needed.

Heat may be generated by a burner 12 combusting fuel under the directionof the controller 11, 24 as shown in FIG. 2, in which case thecontroller 11 is configured to cooperate with the burner controller 24to fire the burner to pre-heat the chamber 7 surrounding the heatexchanger 6. In some embodiments of the disclosed systems 100, 200, theburner 12 is a burner configured for use in a residential boiler orheating system, and is preprogrammed with safety checks to confirm safeoperation of the burner 12. Safe operation of the burner 12 is reportedto the system controller 11 at startup by the burner controller 24. Itis an objective of the control system that the water absorbs sufficientenergy and phase change to steam before it can collect as water dropletson the inside wall of the heat exchange tube. If water drops collect inliquid form, they can then pool inside the heat exchanger and causesystem instabilities and inefficiencies. In one embodiment of a heatexchange tube 30 as shown in FIG. 10, water is injected at the top endof a helical coil, and the water flows down the coil, spreading andabsorbing heat. Situating the nozzle 5 in a position where gravityassists in spreading the water along the heat exchange tube 30 mayprevent pooling of liquid phase working fluid. As steam moves along theremainder of the coiled tube 30 as a gas, it absorbs more heat, andbecomes dry super-heated steam.

FIG. 2 illustrates one embodiment of an on demand steam generatingsystem 100 incorporated into a combined heat and power (CHP) system 200.The basic system 100 of a working fluid reservoir 1, water pump 3 drivenby BLDC motor 32, check valve 4, nozzle 5, heat exchanger 6, combustionchamber 7, burner 12, sensors 8, 9 and controller 11 operate in a mannerdescribed above with respect to FIG. 1. The basic system 100 is arrangedto deliver steam to a turbine-powered electrical generator 15 togenerate electrical energy. A coolant pump 21 circulates coolant 23through an exhaust gas heat exchanger 19 and a condenser 17 to collectheat energy from the heated combustion (exhaust) gasses leaving thecombustion chamber and from the low pressure steam leaving the exhaustof the steam turbine 15, respectively. Coolant 23 is circulated througha heat exchanger 20 and the heat harvested from the condenser 17 andexhaust gas heat exchanger 19 is used to satisfy a heat load such asheating a building or for some other purpose, increasing the overallefficiency of the CHP system 200.

In the disclosed system 200, the water pump motor 32 and the burnerblower motor 34 are both variable output motors whose output isproportional to applied power. In the case of the burner blower motor34, the burner 12 is configured to meter fuel according to the powerapplied to the blower motor 34, so in the disclosed system 200, powerapplied to the burner blower motor 34 is a proxy for heat energy inputto the combustion chamber 7. Power applied to the water pump motor 32and burner blower motor 34 is varied using pulse width modulation (PWM)as is known in the art. Other methods of motor control may be employedand the disclosed control scheme is intended as a non-limiting example.

The disclosed system 200 is a “closed loop” working fluid system that issealed, eliminating the need for added “make up” working fluid. Onceassembled and before being sealed, the water tank 1, water pump 3, heatexchanger 6, turbine 15, condenser 1 and associated fluid flow conduitsare evacuated and then the water tank 1 is filled, or “charged” with apre-determined volume of de-gassed, distilled water. The system 200 isintended to remain sealed and operate using the same quantity of workingfluid, but can be unsealed for service as necessary. Evacuating andsealing the system 200 ensures that the system is filled with only waterand water vapor, and eliminates the need for a vacuum pump (such as 18shown in FIG. 2) to maintain low pressure at the outlet of the turbinedriving the electrical generator 15. Low pressure steam 16 leaving theturbine 15 is cooled and condensed in condenser 17 back to liquid waterand returned to the coolant reservoir 1. Use of distilled water as aworking fluid can reduce fouling and build up in the heat exchange tubes30 due to dissolved minerals present in most water. Further, re-use ofthe working fluid 2, 10, 16 means that any residual heat left after theturbine exhaust 16 is condensed is heat energy that does not need to beadded to convert the liquid water back to steam, which increases theefficiency of the CHP system 200.

The combustion chamber 7 is an area where heat is contained andconcentrated, facilitating transfer of heat to the heat exchange tube ortubes 30 and the water and steam within the tube. The chamber 7, whichmay be referred to as “the combustion chamber,” is not limited tocombustion only. Heat may be provided from an outside source, in whichcase the combustion chamber 7 provides an environment for the heat tosurround and raise the temperature of the heat exchanger 6. The heatexchanger 6 is a device which facilitates the transfer of heat energy tothe working fluid to phase change from liquid to gas and accumulatepressure. In the embodiment illustrated in FIG. 2, the heat exchanger 6is one or more tubular metal coils 30 such as that illustrated in FIG.10, which can withstand the temperatures and pressures of the combustionchamber and the gaseous working fluid 10. The geometry and material ofthe heat exchanger 6 and heat exchange tubes 30 can vary depending uponspecific variables, including but not limited to: the rate at which heatis transferred from the chamber 7 to the working fluid in the heatexchange tube(s) 30, the volume, pressure and temperature of the gaseousworking fluid output, spatial constraints, and economic factors such asmaterial costs and manufacturing considerations. The heat exchanger 6can be, but is not limited to a circular cross section metal coil, afinned tube, flat tube, or shell and tube heat exchanger, etc. A heatexchange tube in the form of a coil surrounding a vertical axis may havethe nozzle 5 for delivering liquid phase working fluid arranged at anupper end of the tube. Injecting liquid phase working fluid (water) atan upper end of the tube 30 allows the liquid phase working fluid toflow and spread along the tube by gravity to enhance heat transfer fromthe tube to the working fluid.

A controller 11 compatible with the disclosed on-demand vapor generatoris operatively connected to the burner 12, working fluid pump 3, andsensors 8, 9 arranged to sense various conditions in the vapor generator100, 200. As shown in FIG. 4, a controller 11 includes a processor(CPU), memory, inputs, outputs, a power supply and a communicationinterface for installing or changing the operating program. Thecontroller 11 is configured to cooperate with a controller 24 for theburner 12, allowing the use of an “off the shelf” burner available forresidential or commercial boilers. Commercially available burners meetregulatory requirements for safety, so configuring the systems 100, 200to use commercially available burners simplifies regulatory compliance.Some parts of the description may refer to “controller 11, 24” meaningthat the system controller 11 is configured to coordinate with theburner controller 24 to manage the generation of heat for the system100, 200. A suitable controller can be constructed using a computer or amicrocontroller or microprocessor and memory according to the preferenceof a designer. An operating program, to be executed by the controllers11, 24 may be one or more sets of code executed separately incontrollers 11 and 24, with operation of the burner controller 24responsive to commands from the system controller 11. The systemfirmware may include one or more program loops such as those illustratedin FIGS. 5-9. Primary objectives of the controller are to: 1) managecold start-up of the system to quickly achieve a stable steam flowoutput without human intervention; 2) monitor system operation, makingadjustments as necessary to maintain stable steam production; 3) adjustsystem operation in response to changes in demand for steam; and 4) takecorrective action or shut down the system in the event of an unsafe orunstable condition.

Sensed conditions internal to the vapor generator include temperatureTEMP and pressure P in the heat exchange tube 30. The control systemincludes a sequence for starting the disclosed on-demand vapor generatorfrom a cold state. One start up sequence illustrated in FIG. 5 includesoperating the burner 12 and pump 3 according to a pre-determined“initial” set point while monitoring temperature TEMP at or near theoutlet of the heat exchanger 6. The initial set point includes aninitial heat set point and an initial fluid flow set point correspondingto a pre-determined flow of gaseous phase working fluid at apre-determined temperature and pressure. The initial set point and startsequence shown in FIGS. 5 and 6 are selected to safely manage the systemfrom a cold start to steady state operation at a low rate of vaporproduction. When the system has achieved steady state operation, thecontroller is programmed to shift to the steady state control loopsshown in FIGS. 7, 8 and 9.

According to the algorithm illustrated in FIG. 5, the controller 11first conducts some safety checks to ensure that there are no errorsfrom the burner controller 24, sufficient water is present in the waterreservoir 1, etc. If there are no safety issues, the controller 11operates the burner 12 at an initial heat set point and the pump 3 at aninitial fluid flow set point, where the burner 12 may be started beforethe pump 3 to allow the combustion chamber 7 and heat exchanger 6 towarm up. The controller 11 monitors the temperature TEMP at the outletof the heat exchanger 6 and adjusts operation of either the pump 3 orthe fuel burner 12 while operating the other of the pump 3 or fuelburner 12 at its initial setting. As shown in FIGS. 5 and 6, thecontroller 11 compares a sensed condition such as temperature TEMP witha desired level T for the sensed variable and determines the differencebetween sensed condition TEMP and the desired level T, where thedifference ΔT can be positive when the sensed condition TEMP is greaterthan the desired level T or negative when the sensed condition TEMP isless than the desired level T. It will be noted that ΔT is calculateddifferently in FIGS. 5 and 6 to account for the fact that, whencontrolling the variable TEMP, increased fluid flow acts to reduce TEMP,while increased heat energy acts to increase TEMP. The controller 11 isprogrammed to apply a correction factor to operation of the fuel burner12 or pump 3, where the correction factor is a combination of apre-determined constant multiplied by the difference between the sensedcondition and the desired level, or in this example ΔT. The controller11 is programmed to monitor the sensed condition and adjust operation ofthe fuel burner 12 or pump 3 until the sensed condition remains within apre-determined range for a pre-determined period of time. If the sensedcondition is temperature T in the heat exchanger, then one example of apre-determined range might be a range of +/−15° F. for a period of 20 to40 seconds. FIG. 5 illustrates a startup algorithm where the burner isoperated at the initial set point and fluid flow is modulated byapplying a fluid flow correction factor to the power applied to the pumpmotor 32. According to aspects of the disclosure, the constant X used inthe fluid flow correction factor is very small, for example 0.05. Theresulting fluid flow correction factor will vary with ΔT, but willalways be small. Small adjustments made many times per second allow thedisclosed controller to quickly stabilize the variable TEMP within thedesired range without large swings or oscillations. The constant X maybe different in the steady state algorithm of FIG. 7. One representativeexample might be 0.02. The value of constant X in the startup algorithmof FIG. 5 is larger because the circumstances call for greater change inTEMP during startup, while the smaller constant should be sufficient forsteady state operations where TEMP does not need to change as much.

FIG. 6 illustrates a startup algorithm where the pump 3 is operated atthe initial set point and the burner is modulated by applying a heatcorrection factor applied to the control signal from the controller 11to the burner 12, where the control signal may be power varied usingPWM. The constant Y used in calculating the heat correction factor has afirst value Y1 when T is greater than TEMP (calling for reduced heatinput) and a second value Y2 when T is less than TEMP (calling forincreased heat input). To reduce the chance of temperature overshoot, Y1is greater than Y2. Constants Y1 and Y2 may also be smaller duringsteady state operation when heat input is modulated to control TEMP,than during startup.

FIG. 7 illustrates a steady state control loop where the system 200 isoperated at a set point corresponding to current demand for the combinedoutput of the system, e.g., electricity and/or heat. In FIG. 7, heatoutput is held at the demand set point and water flow is modulated byapplying a steady state fluid flow correction factor to the powerapplied to the pump motor 32. The variable TEMP is compared to thedesired temperature T and the steady state fluid flow correction factoris calculated and the pump operation is adjusted accordingly. Note thatthe constant X used in calculating the fluid flow correction factor maybe different in the steady state control loop of FIG. 7 than it is inthe startup control loop of FIG. 5. In FIG. 7, a change in demand causesthe controller 11 to look up a new set point corresponding to the newdemand. The pump and burner are operated according to the new setpoints, with water flow varied by application of the fluid flowcorrection factor calculated as discussed above. Water flow is varied atthe new set point to control TEMP within a predetermined range of thedesired temperature T until there is another change in demand. Thesteady state control algorithm of FIG. 7 would be used in a systemconfigured to use water flow to control steam temperature, and iscompatible with the startup algorithm of FIG. 5. FIG. 8 illustrates asteady state control algorithm that modulates heat output to controlsteam temperature TEMP, and is compatible with the startup algorithm ofFIG. 6. Constant Y may be smaller in the steady state control algorithmof FIG. 8 than in the startup control algorithm of FIG. 6.

According to aspects of the disclosure, when the hardware of anon-demand vapor generator 100 has been selected and assembled into a CHPsystem 200, the vapor generator 100 is operated to characterize or mapbehavior of the vapor generator 100 over a range of operatingconditions. For example, the pump 3 is operated at a set point and thefuel burner 12 is operated over a range of settings to determine a heatsetting which results in a steady state flow of gaseous phase workingfluid for the flow of liquid phase working fluid corresponding to thepump flow rate. Steady state as used in this disclosure is a flow ofgaseous phase working fluid that remains within a 40° F. temperaturerange (+/−20° F. of a target temperature T) and within a 10% range ofgaseous phase working fluid pressure for a pre-determined period oftime. The pre-determined period of time may range from 10 seconds to oneminute, depending upon system configuration. This process is repeated ata range of pump settings corresponding to expected operating conditionsof the on-demand vapor generator, a corresponding heat setting isdetermined for each pump setting, and the pump settings and heatsettings are saved into memory as “set points” each including a pumpsetting and a heat setting. This process can be repeated with the fuelburner 12 operated at a range of heat settings corresponding to expectedoperating conditions of the on-demand vapor generator 100, and thecorresponding pump setting for each heat setting is established andsaved into memory. This process may result in one or more “maps”relating fluid flow to heat input for a specific CHP systemconfiguration. At least one of these “maps” is saved into the memory ofthe controller for use in control algorithms such as those illustratedin FIGS. 5-8. When the vapor generator 100 is incorporated into a CHPsystem 200, the pump and heat settings may correspond to the expectedrange of heat and electrical output from a “startup” setting to settingscorresponding to maximum output. In this disclosed control method, oneof the pump or burner are operated at a fixed setting and the other ofthe pump or burner are modulated to determine the other part of thecontrol set point. In the disclosed embodiment, the set pointscorrespond to a duty cycle (PWM signal corresponding to applied power)to be applied to the water pump motor 32 and the burner blower motor 34.Power applied to water pump motor 32 corresponds to line pressure at thenozzle 5 and a mass flow of water through the nozzle (which will varyaccording to back pressure). Power applied to burner blower motor 34corresponds to heat energy released into combustion chamber 7, asdescribed above. The purpose of the initial set point is to give thecontroller 11, 24 initial operating parameters until system parametersstabilize, allowing a shift to the steady state algorithms of FIG. 7, 8or 9.

As the steam 10 leaves the heat exchanger 6, a temperature sensor 9 suchas a thermocouple and/or a pressure sensor 8, such as a pressuretransducer read the steam parameters (temperature and pressure) andrelay corresponding pressure and/or temperature signals to thecontroller 11. Multiple temperature and/or pressure sensors may be usedto improve the accuracy or detail of sensed conditions in the system100, 200. The disclosed systems 100, 200 may take 40 readings per secondand average the readings over a one second period to arrive at ameasured value for temperature and pressure. Averaging multiple sensorreadings can reduce the effect of erroneous readings. Other sensors,such as a mass flow meter on the water pump 3 could be employed toprovide information to the controller 11.

Water transitions to steam and expands rapidly, increasing the pressurein the heat exchange tube 30 adjacent the nozzle 5. As the steam 10fills the heat exchange tube and connected steam lines, the pressurewithin the heat exchange tube 30 increases, resulting in higher pressureopposing the injection of water from the nozzle 5. Changes indifferential pressure across the nozzle 5 result in changes in the flowof water through the nozzle 5. The water pump motor 32, water pump 3,nozzle 5, and heat exchange tubes 30 are selected so that the water pump3 can generate sufficient differential pressure across the nozzle 5 toovercome increased back pressure from steam being generated in the heatexchange tube 30. Increased differential pressure across the nozzle 5results in increased water injection and increased steam flow, assumingsufficient heat energy to transition the injected water 2 to steam 10.Decreased differential pressure reduces water flow through the nozzle 5,resulting in a reduced demand for heat energy to transition the reducedflow of water 2 into steam 10, which requires adjustment of the burner12 to prevent overheating. The water pump motor 32 is selected to havethe capability of generating pressure at the nozzle 5 sufficient toovercome the back pressure in the heat exchange tube 30 at apre-determined maximum steam output pressure. An alternative designcould employ an active nozzle that would respond to signals from acontroller to turn on, turn off or modulate flow through the nozzle.Such a nozzle would present control modalities in addition to thosediscussed in the present embodiments. Different arrangements of hardwarecan be operated and mapped as described above. Alternative systemconfigurations will have operating parameters dictated by componentconfigurations and operating requirements.

One example of initial set point values are a 25% duty cycle applied tothe burner blower motor 34 and a duty cycle applied to the water pumpmotor 32 sufficient to produce about 4.6 mL/sec. water flow throughnozzle 5. One example of an equation for water flow is:5.0166*Ln(Pressure)−15.111, which was derived by measuring water flowneeded to keep the steam temperature at 400° F. at multiple pressures,then adding a best fit curve. These initial set point valuesconsistently bring the steam pressure up to 50 psi without overheatingthe system. These values are employed in a system using onlyproportional control equations. One factor affecting system stability isa lag in temperature readings from thermocouple-type temperaturesensors. In a system using proportional control, it is possible to add acorrection factor to the duty cycle applied to the water pump motor 32to minimize temperature overshoot caused by thermocouple lag. Oneexample of a correction factor is a value of 0.015*(TEMP−400), with TEMPbeing the thermocouple reading and 400 being the desired stabletemperature of output steam. The resulting correction is positive whenthermocouple readings are greater than 400° F. and negative when thereadings are less than 400° F. Use of proportional-integral-derivative(PID) control as shown in FIG. 9, is one alternative to the controlalgorithms of FIGS. 5-8.

Pressure control is similar to water flow control but is linked to theduty cycle applied to the burner blower motor 34, since the energyreleased into the combustion chamber is directly related to the burnerblower motor duty cycle. A pressure transducer 9 measures pressurebefore the turbine and takes an average of multiple measurements. Theaverage measured pressure is compared to the desired pressure and a heatcorrection factor as shown in FIG. 6 is applied to the blower motor dutycycle. The system 100, 200 may use different constants when calculatinga correction factor to reduce the likelihood of temperature overshoot.For example, during startup when the average measured value is less thanthe desired pressure (calling for increased heat input), the correctionconstant is 0.007, and when the average measured value is greater thanthe desired pressure (calling for reduced heat input), the correctionconstant is 0.015. During steady state operation, the correspondingvalues are 0.01 and 0.015, respectively. In both cases, the correctionconstant is smaller for situations calling for increased heat than it isfor situations calling for decreased heat.

In one example, the initial set points allow the system to safely reach50 psi, at which point the blower motor duty cycle is reduced to 22%.Once the system drops to 43 psi at the 22% duty cycle, automatic controlis enabled, allowing the blower motor duty cycle to slowly increase byusing a proportional gain equation until steam pressure steadies at 50psi. To verify the system is stable, pressure boundaries of 48.5 psi and51.5 psi and temperature boundaries of 380° F. and 415° F. areestablished. Once the system stays within those boundaries for 20-40seconds, the system is considered stable and is allowed to ramp up inpressure to the desired value. When ramping up steam pressure underproportional gain control, the set point may be increased by 1 psiincrements, allowing the pressure to rise to within 1.5 psi of the setpoint for 2 seconds before increasing the set point by another 1 psi.Similar methods may be used during pressure decrease. Alternatively,when entering steady state control, a set point corresponding to thecurrent demand may be selected, and system operation shifted to that setpoint as shown in FIGS. 7 and 8, rather than being ramped incrementally.

Valves 13 and 14 are arranged to control when steam is delivered to theturbine 15. During startup, the first steam produced will be too cooland wet to be used in the turbine, so valve 13 is open and valve 14 isclosed, diverting steam 10 around the turbine 15 to condenser 17. Whentemperature and pressure signals from sensors 8 and 9 are within a rangesuitable for the turbine 15, controller 11 closes valve 13 and opensvalve 14, routing steam through the turbine to perform work such asgenerating electricity. This would typically occur upon entering thesteady state control loops at the conclusion of FIG. 5 or 6. Valves 13and 14 could be replaced with a steam trap or a clean steam separator(not shown), which would provide the similar functionality as valves 13and 14 operated by controller 11. The system 200 and controller 11, 24are configured to protect the micro steam turbine from input steam thatcould damage the turbine. Steam that is too cool and wet or steam thatis too hot will damage the turbine, so the system 200 and controller 11,24 are configured to produce superheated dry steam at an outputtemperature range of between 350° F. and 400° F., ideally approximately400° F. Steam temperatures below 250° F. or above 450° F. represent theabsolute boundaries of acceptable input steam for the micro steamturbine 15. The system 200 and controller 11, 24 are arranged to produceand deliver steam in the heart of the acceptable range and to preventdamage to the turbine from exposure to steam having properties outsidethe acceptable range.

To the steam generator 100, the attached expander appears as a flowrestriction resisting flow of steam away from the nozzle end of the heatexchange tube 30. Except for an initial spin up of the turbine 15, theflow restriction should be fairly consistent, allowing the controller toenter a steady state control loop illustrated in FIGS. 7 and 8. Oneexample of a steam turbine 15 requires a flow of super-heated 400° F.dry steam at approximately 75 psi, and the controller 11, 24 isconfigured to balance the mass flow of water with applied heat energy togenerate sufficient steam volume to maintain the required outputtemperature and pressure against the flow restriction of the turbine 15.For any given expander, the volume of steam generated at the output ofthe heat exchanger 6 during operation is balanced against the volume ofsteam passing through the expander, resulting in a steam pressure atpressure sensor 9. Increased steam production will tend to increasepressure at sensor 9 and increase the resulting work at the expander 15,while reduced steam production has the opposite effect. Alternatively,valves 13, 14 could be employed to control the volume of steam deliveredto the turbine 15, and the resulting work performed, e.g., electricalenergy generated by the electrical generator driven by the turbine 15.As previously described, when sensors 8, 9 report the presence of steamtemperature and pressure at the outlet of the heat exchanger 12 that aresuitable for the turbine 15, controller 11 opens valve 14, closes valve13 and enters a steady state control loop at 70.

An alternative example of a steady state control loop is illustrated inFIG. 9. In this example, the steady state control loop includes twooverlapping subroutines 72, 74. The disclosed control loops 72, 74incorporate proportional, integral, derivative (PID) calculations toguide actions of the controller, with the objective being a stableoutput of steam at the correct temperature and pressure. Use of PIDcalculations in control loops is well known to those skilled in the artand will not be described in detail here. PID control can preventexcessive correction (overshoot), which can lead to undesirable systemoscillations and instability. Using the mass flow of water as derivedfrom operation of the water pump 3 (as described above) and/or a massflow sensor (not shown), the controller 11 can then calculate how muchheat is needed so the water flow entering the heat exchange tube 30 canphase change to steam before leaving the heat exchanger 6. Thecontroller 11, 24 balances the injection of water with the addition ofheat energy to produce a steady flow of steam having the correctpressure and temperature for use in the turbine 15. In the controlmethod of FIG. 9, an electronic feedback loop maintains a steady statepressurized steam flow “set point” by adjusting the mass flow of waterinjected as well as the heat energy available in the combustion chamber7 in response to signals from sensors 8 and 9.

In an embodiment of the disclosed on demand steam generating systemsemploying the steady state control loop of FIG. 9, the injection ofwater and the application of heat interact to produce the desired flowof steam, so the steady state program loop employs subroutines 72, 74which constantly adjust power applied to the burner blower motor 34 andthe water pump motor 32. At block 72, if steam pressure is not at theset point, controller performs a PID calculation to arrive at acorrection to the blower motor duty cycle at 76, which roughlycorresponds to heat energy input to the combustion chamber 7. The blowermotor duty cycle is updated with the calculated correction at 78. Thecontroller then calculates the water pump motor duty cycle based on thepressure sensor reading at 80 and updates the water pump motor dutycycle at 82. The program loop then checks the steam temperature at 84.If the measured temperature is not correct, the controller performs aPID calculation to arrive at a correction to the water pump motor dutycycle at 86 and updates the duty cycle of the water pump motor at 88. Atthe end of subroutine one (steps 72 and 76-88) the control loop returnsto the beginning and checks steam pressure again at 72. If steampressure is correct, then steam temperature is checked at 74. If steamtemperature is not at the set point, then the controller performs a PIDcalculation to arrive at a correction to the water pump motor duty cycleat 90 and updates the water pump motor duty cycle at 92. At the end ofsubroutine two (steps 74, 90 and 92) the control loop returns to thebeginning and checks steam pressure at 72. The steady state control loopof FIG. 9 runs continuously during operation of the system 100, 200,repeating many thousands of times per second to maintain the requiredflow of steam at a predetermined temperature and pressure. While acontrol feedback loop with PID control calculations to stabilize steamoutput is described, the disclosed systems are not limited to thiscontrol scheme.

There are a variety of expanders that can be used to produce work fromthe flow of energetic gaseous working fluid produced by the disclosedsystems, including a piston engine, Wankel engine, micro or large scalesteam turbines, etc. Each expander may require specific system features,such as lubrication oil, downstream pressure drops to draw condensatethrough the expander, etc. The system illustrated in FIG. 2 employs acondensing micro steam turbine which requires no oil lubrication butdoes require negative pressure on the exhaust to draw out anycondensate. This alleviates any back pressure to the turbine, providingmaximum efficiency. The system configuration will change based upon thechosen expander and system functionality, with the disclosed on demandsteam generator and control system operating according to the same basicprinciples.

The disclosed on demand vapor generating system 100, or CHP system 200require a set point for work output. The work output set point is basedupon the system's work output requirement, or “demand.” When thecontroller 11 recognizes the work output requirements either through apreprogrammed input, a user interface where a set point value can beprogrammed, or through electrical or mechanical load recognitionfeatures such as a thermostat or demand for electrical energy, thesystem will identify a set point for the desired work output. The flowof water and heat input are calculated and controlled to generate a flowof steam corresponding to the desired set point of work output. Thedisclosed systems 100, 200 include controllers 11, 24 programmed torespond to changes in load by establishing a new set point and adjustingoperation of the system to generate steam output corresponding to therequired work output, within system limitations. Steam output is matchedto demand on a continuous basis, according to aspects of the disclosure.

Once the steam 10 begins to flow to an expander such as turbine 15, workoutput can be measured by many different variables (current, voltage,RPM, etc.). Work output at an expander may be measured by the controllerand used to calculate the correct heat input and/or water mass flowrequired to maintain the corresponding steam production. System 200 isconfigured to monitor steam temperature and/or pressure at the outlet ofthe heat exchanger 6 and to maintain these parameters at valuescorresponding to a demand for work.

The disclosed CHP system 200 will not only generate electricity but alsoproduce residual heat that can be recovered as useful heat for hotwater, facility heat, or other uses as shown in FIG. 2. In a CHPconfiguration such as that shown in FIG. 2, the overall systemefficiency can be increased to over 95% and as high as 99% by recoveringthe normally wasted residual heat for other uses (Systemefficiency=(Electricity out+Heat recovered)/Fuel burn). In FIG. 2, theheat exchanger 20 arranged to remove heat from the coolant 23circulating in the coolant loop 17, 19, 20, 21 can be a forced airliquid-to-air heat exchanger, or a liquid-to-liquid heat exchanger in ahydronic heating system. The heat exchanger 20 can be arranged toprovide either forced hot air or radiant heat to a dwelling. The coolingloop can also be replaced or complimented by a domestic hot water tankthat will absorb and temporarily store heat that would otherwise bewasted. Coolant 23 may be circulated first through condenser 17 andsubsequently through exhaust gas heat exchanger 19, because a greatertemperature differential between turbine exhaust 16 and coolant 23 isdesirable for efficient condensation of turbine exhaust 16.

CHP systems 200 incorporating the disclosed on demand vapor generators100 may be configured with the capability of producing heat energygreater than needed for steam production, with the excess heat energyemployed for other purposes. For example, if a CHP system is configuredwith a burner closely matched to the selected expander, there will bemodest excess heat collected in the coolant, since most of the heat willbe absorbed in the heat exchanger 6. In such an arrangement, the heatrecovered in the coolant loop may be insufficient to meet demand forheat, for example to heat a structure on a cold day. Under suchcircumstances, an additional heat source would be necessary, duplicatingmuch of the structure of the burner 12 and combustion chamber 7 alreadyincluded in the disclosed systems 100, 200. Providing a more robust heatsource permits more widespread use of a CHP, and may reduce or eliminatethe need for supplementary heat sources according to aspects of thedisclosure. The heat source such as burner 12 and coolant loopcomponents 17, 19, 20, 21 can be designed to allow for the proper amountof heat to be absorbed in the coolant 23 to serve the additional heatdemand and eliminate the need for an additional heat source. Designing asingle combustion chamber 7 and heat source such as burner 12 that cangenerate heat energy sufficient to meet the full thermal load for agiven installation provides a significant economic advantage byeliminating the equipment cost of the second heating source.

There are also applications where the thermal load is not required andthe on-demand vapor generating system 100 is used to perform mechanicalwork or generate electrical energy. In such an application, the coolingloop will have the same functionality except the heat from the coolingfluid heat exchanger 20 would vent to the atmosphere instead of beingused for some other purpose. In such circumstances, it is possible toconfigure a cooling loop extracting heat from the combustion chamberexhaust at 19 and the expander exhaust at 17 and add some of that heatenergy into water delivered to the nozzle 5 in an “economizer”arrangement. Raising the temperature of the working fluid beforeinjection reduces the amount of time and heat energy necessary totransition the water into steam, increasing system efficiency. It may bepossible to raise the temperature of the water past its boiling point,in which case at least some of the water would “flash” directly to steamupon passing through the nozzle 5.

The disclosed on demand vapor generator and control system may also beused to harvest waste heat energy from an existing heat source ratherthan burning a fuel inside a combustion chamber. This method fordeveloping steam can be added to any system that produces waste heat,e.g. large internal combustion generators, kilns, industrial furnaces,etc. The system of FIG. 2 could be modified to work with an existingheat source. The combustion chamber 7 would not have a combustion sourcesuch as burner 12 and would not burn any fuel to produce heat. The heatexchanger 7 would be placed in a position (a flue or exhaust pipe) to beheated by exhaust from the original system before it is vented to theatmosphere. These exhaust gases generally carry a large amount ofenergy, normally wasted, which can be recovered. Approximately 30% ofthe heat generated by an internal combustion engine is wasted into theexhaust, which also tends to be relatively high temperature. The exhaustof internal combustion engines presents a large opportunity to recoverywaste heat according to aspects of the disclosure.

In one disclosed embodiment of a control system, steady state workoutput is achieved by, but is not limited to, two closed-loop controlalgorithms operating together as shown in FIG. 9. Both control loopsmeasure system variables and use that feedback to calculate adjustmentsto system variables to produce the desired steam output, as describedabove. The control routines may provide feedback to each other byincorporating the output of one control loop with the input or output ofthe other control loop. One objective of the control loops is to producethe desired work output using a calculated amount of heat input whilekeeping the steam within the desired range of steam temperature andpressure. The disclosed apparatus and control system improve over theprior art by matching work output with heat energy input, efficientlymaintaining a flow of steam in the superheated temperature range whilehaving the capability to quickly change work output as desired. If achange in work is required by the system, the control loops recognizethe change in load and set the work output (set point) to the newdesired load and maintain that output for the required period of time.

Once steam phase changes to its superheated properties, steam acts as anideal gas. Following ideal gas laws and keeping volume constant,pressure and/or temperature can be monitored to regulate the mass flowof water according to the equation (PV=nRT). Subroutines 1 and 2 shownin FIG. 9 are linked by the physics of the system. The governingequation for subroutine 1 is: W=Q where W is work output and Q is heatinput. The governing equation for subroutine 2 is: Q=m*C_v*(T_2−T_1).

Using the two governing equations of heat transfer and thermodynamicsabove where heat input, Q, is equal to the mass flow of the water m,multiplied by the specific heat of the water, C_v, multiplied by thechange in water temperature. Also where work output, W, is equal to heatinput, Q. T2 represents the steam temperature after heat is added to thesystem and T1 is the temperature of the water before it enters the heatexchanger to phase change to steam. The control program does notcalculate the exact amount of heat required; instead the controller mayuse equations incorporating these principles to continually adjust themass flow of water and heat input to keep the system at steady state inresponse to changes in system variables and demand for work (whichaffects set point). In one control algorithm, the system will set theheat input Q to an initial set point corresponding to a desired workoutput and then slowly increase the mass flow of water (m). Thetemperature and pressure of the resulting steam will begin to be read bythe controller via signals from sensors 8, 9. As T2 temperature risespast its set point the controller will add more water and T2 will dropas excess heat is absorbed by the injected atomized water. Again as thesystem reaches steady state T2 will rise. This process will repeat untilthe steam temperature T2 is stable, meaning that temperature remainswithin a predetermined range of the steady state set point. Once thetemperature stabilizes, the required power will be monitored and if thepower output is not at the correct set point, heat will be increased ordecreased to accommodate the power demands. This will change the T2temperature and the control loop illustrated in FIG. 9 will beginstabilizing steam temperature T2 again through the mass flow of water.Although this sounds like a lengthy process, with instant controllerfeedback times and almost instantaneous computing speeds, this processcan be executed rather quickly and steady state flow of steamcorresponding to a desired work or power output can be achieved in lessthan 1 minute.

The equations are used to represent relationships between the variables.They are not accurate for mathematical calculation. When phase changingfrom water to steam, each phase has a different specific heat. If theseequations where used for the phase change from water to steam it wouldmathematically be incorrect. However these equations can be used torepresent the correlations between heat input, work output, temperatureand flow, which are the correlations the controller needs to correctlyoperate.

Embodiments of the disclosed on demand steam generating systems areshown and described for purposes of illustration. The disclosedembodiments are examples and are not intended to limit the scope of theappended claims. Variations of the disclosed structures, functions, andcontrol methods will occur to those skilled in the art, all of which areintended to be encompassed by the claims.

What is claimed:
 1. A system for generating a variable flow of gaseousphase working fluid, comprising: a heat exchange tube arranged in acombustion chamber, said heat exchange tube having a first end receivingliquid phase working fluid and a second end from which gaseous phaseworking fluid leaves the heat exchange tube; a variable output heatsource arranged to release a variable quantity of heat into saidcombustion chamber, said variable quantity of heat being a function ofpower applied to said variable output heat source, said heat beingabsorbed by said liquid phase working fluid which transitions to agaseous phase working fluid in said heat exchange tube; a variable flowrate source of liquid phase working fluid arranged to deliver liquidphase working fluid to the first end of said heat exchange tube, a flowrate of said variable flow rate source being a function of power appliedto said variable flow rate source; an expander in a gaseous phaseworking fluid pathway connected to said heat exchange tube second end,said expander using said variable flow of said gaseous phase workingfluid at a pre-determined target temperature T to perform work; atemperature sensor arranged to generate a temperature signal TEMPcorresponding to the temperature of said gaseous phase working fluid insaid gaseous phase working fluid pathway; a controller operativelyconnected to said variable output heat source, said variable flow ratesource of working fluid and said temperature sensor, said controllerexecuting a program, said program comprising: retrieving an initial setpoint from memory, said initial set point including an initial heatpower level and an initial flow rate power level; applying said initialheat power level to said variable output heat source; applying saidinitial flow rate power level to said variable flow rate source;receiving said temperature signal TEMP; calculating a fluid flowcorrection factor according to the formula X*ΔT, where X is apredetermined constant and ΔT is calculated according to TEMP−T;adjusting the initial flow rate power level by an amount equal to thefluid flow correction factor to provide an adjusted flow rate powerlevel and operating said variable flow rate source according to theadjusted flow rate power level while operating said variable output heatsource according to said initial heat power level, or calculating a heatcorrection factor according to the formula Y*ΔT, where Y is apredetermined constant and ΔT is calculated according to T−TEMP;adjusting the heat power level by an amount equal to the heat correctionfactor to provide an adjusted heat power level and operating saidvariable output heat source according to the adjusted heat power levelwhile operating said variable flow rate source according to said initialflow rate power level, wherein said steps of operating, receiving,calculating and maintaining are performed in a control loop runningcontinuously until said TEMP stabilizes within a pre-determined rangerelative to said target temperature T for a pre-determined period oftime.
 2. The system of claim 1, wherein said predetermined constant Yhas a first value Y1 when T is greater than TEMP and a second value Y2when T is less than TEMP.
 3. The system of claim 1, wherein powerapplied to said variable output heat source and said variable flow ratesource is varied using pulse width modulation (PWM) and said initialheat power level is a PWM duty cycle applied to said variable outputheat source, said initial flow rate power level is a PWM duty cycleapplied to said variable flow rate source.
 4. The system of claim 1,wherein said initial flow rate power level produces a flow rate ofliquid phase working fluid generating a flow of gaseous phase workingfluid from said heat exchange tube second end at said predeterminedtarget temperature T when exposed to a quantity of heat corresponding tosaid initial heat power level.
 5. The system of claim 1, wherein theliquid phase working fluid is water, said gaseous phase working fluid issuperheated steam, said expander is a steam turbine operativelyconnected to drive an electric generator, said system comprising: acondenser fluidly connected to an outlet of said steam turbine, where insteam leaving the steam turbine is cooled and condensed to liquid form,resulting in reduced pressure at the outlet of said steam turbine.
 6. Asystem for generating a variable flow of gaseous phase working fluid,comprising: a heat exchange tube arranged in a combustion chamber, saidheat exchange tube having a first end receiving liquid phase workingfluid and a second end from which gaseous phase working fluid leaves theheat exchange tube; a variable output heat source arranged to release avariable quantity of heat into said combustion chamber, said variablequantity of heat being a function of power applied to said variableoutput heat source, said heat being absorbed by said liquid phaseworking fluid which transitions to a gaseous phase working fluid in saidheat exchange tube; a variable flow rate source of liquid phase workingfluid arranged to deliver liquid phase working fluid to the first end ofsaid heat exchange tube, a flow rate of said variable flow rate sourcebeing a function of power applied to said variable flow rate source; anexpander in a gaseous phase working fluid pathway connected to said heatexchange tube second end, said expander using said variable flow of saidgaseous phase working fluid at a pre-determined target temperature T toperform work; a temperature sensor arranged to generate a temperaturesignal TEMP corresponding to the temperature of said gaseous phaseworking fluid in said gaseous phase working fluid pathway; a controlleroperatively connected to said variable output heat source, said variableflow rate source of working fluid and said temperature sensor, saidcontroller executing a program, said program comprising: retrieving aninitial set point from memory, said initial set point including aninitial heat power level and an initial flow rate power level; applyingsaid initial flow rate power level to said variable flow rate source;applying said initial heat power level to said variable output heatsource; receiving said temperature signal TEMP; calculating a heatcorrection factor according to the formula Y*ΔT, where Y is apredetermined constant and ΔT is calculated according to T−TEMP;adjusting the heat power level by an amount equal to the heat correctionfactor to provide an adjusted heat power level and operating saidvariable output heat source according to the adjusted heat power levelwhile operating said variable flow rate source according to said initialflow rate power level, wherein said steps of operating, receiving,calculating and maintaining are performed in a control loop runningcontinuously until said TEMP stabilizes within a pre-determined rangerelative to said target temperature T for a pre-determined period oftime.
 7. The system of claim 6, wherein said predetermined constant Yhas a first value Y1 when T is greater than TEMP and a second value Y2when T is less than TEMP.
 8. The system of claim 6, wherein powerapplied to said variable output heat source and said variable flow ratesource is varied using pulse width modulation (PWM) and said initialheat power level is a PWM duty cycle applied to said variable outputheat source, said initial flow rate power level is a PWM duty cycleapplied to said variable flow rate source.
 9. The system of claim 6,wherein the liquid phase working fluid is water, the gaseous phaseworking fluid is steam, and the target temperature T corresponds tosteam in a superheated temperature range.
 10. The system of claim 6,wherein said expander comprises a turbine coupled to an electricgenerator.
 11. The system of claim 6, wherein said heat exchange tube iscoiled within said combustion chamber.
 12. The system of claim 6,wherein said variable output heat source is a burner arranged to combustfuel within said combustion chamber.
 13. The system of claim 6, whereinthe liquid phase working fluid is water, said gaseous phase workingfluid is superheated steam, said expander is a steam turbine operativelyconnected to drive an electric generator, and said system furthercomprises: a condenser fluidly connected to an outlet of said steamturbine, in which steam leaving the steam turbine is cooled andcondensed to liquid form, resulting in reduced pressure at the outlet ofsaid steam turbine.
 14. The system of claim 6, further comprising aclosed working fluid path from a reservoir of working fluid, throughsaid heat exchange tube, said steam turbine, said condenser and back tosaid reservoir of working fluid.
 15. A method of generating a flow ofgaseous working fluid comprising the steps of: exposing a heat exchangetube having first and second ends to a variable output heat source, avariable quantity of heat generated by said variable output heat sourcebeing proportional to power applied to said variable output heat source;providing a variable flow rate source of liquid phase working fluid incommunication with a first end of said heat exchange tube, a flow rateof said variable flow rate source proportional to power applied to saidvariable flow rate source and said liquid phase working fluid absorbingheat from said variable output heat source which transitions to agaseous phase working fluid in said heat exchange tube; connecting agaseous working fluid pathway from said heat exchange tube second end toa turbine driven electric generator; measuring the temperature of thegaseous phase working fluid in said gaseous phase working fluid pathwayand generating a temperature signal TEMP corresponding to thetemperature of said gaseous phase working fluid in said gaseous phaseworking fluid pathway; operating said variable output heat sourceaccording to an initial heat power level; operating said variable flowrate source of working fluid according to an initial flow rate powerlevel; receiving said temperature signal TEMP; calculating a heatcorrection factor according to the formula Y*ΔT, where Y is apredetermined constant and ΔT is calculated according to T−TEMP, whereinsaid predetermined constant Y has a first value Y1 when T is greaterthan TEMP and a second value Y2 when T is less than TEMP; and adjustingthe heat power level by an amount equal to the heat correction factor toprovide an adjusted heat power level and operating said variable outputheat source according to the adjusted heat power level while operatingsaid variable flow rate source according to said initial flow rate powerlevel, wherein said steps of operating, receiving, calculating andadjusting are performed in a control loop running continuously untilsaid TEMP stabilizes within a pre-determined range relative to saidtarget temperature T for a pre-determined period of time.
 16. The methodof claim 15, comprising: providing a controller operatively connected tosaid variable flow rate source, said variable output heat source, andsaid temperature signal TEMP, said controller including memory and aprocessor that executes a program including the steps of operating,receiving, calculating and adjusting; deriving a relationship between apower level applied to the variable output heat source and the powerlevel applied to the variable flow rate source by measuring fluid flowneeded to keep said temperature signal TEMP within said predeterminedrange relative to said target temperature T for a given heat output fromsaid variable output heat source at multiple pressures, where theinitial flow rate power level produces a flow rate of liquid phaseworking fluid generating a flow of gaseous phase working fluid from saidheat exchange tube second end within said predetermined range of saidtarget temperature T when exposed to a quantity of heat corresponding tosaid initial heat power level; storing said initial heat power level andsaid initial flow rate power level in said memory as an initial setpoint; and in response to a demand for gaseous phase working fluid,retrieving said initial set point from said memory and using saidinitial heat power level to operate said variable output heat source andsaid initial flow rate to operate said variable flow rate source. 17.The method of claim 16, comprising: after said TEMP has stabilizedwithin said predetermined range of said target temperature T for saidpredetermined period of time, the controller selects a work output setpoint based upon a demand for gaseous phase working fluid, said workoutput set point including a steady state heat power level and a steadystate flow rate power level corresponding to a flow of gaseous phaseworking fluid sufficient to meet said demand.
 18. The method of claim15, wherein said liquid phase working fluid is water and said gaseousphase working fluid is steam, said method comprising: providing acondenser to cool gaseous phase working fluid leaving said turbine,resulting in a flow of water from said condenser; collecting said waterin a reservoir, and evacuating said gaseous phase working fluid pathwayand said steam turbine by application of negative pressure at an outletof said turbine.
 19. The method of claim 18, comprising: connecting saidreservoir to said variable flow rate source, thereby forming a closedloop in which water is recirculated.
 20. The method of claim 15, whereinsaid liquid phase working fluid is water, said gaseous phase workingfluid is steam, and said target temperature T corresponds to drysuperheated steam.